At Onion Lake, we are nearing completion of the phase 2 thermal expansion and we have initiated steam injection to the first pad of wells. We expect to commence steam injection to the second pad in approximately one month. The expansion is expected to add production of 6,000 bbl/d, bringing name plate design capacity of the entire project to 12,000 bbl/d, which we expect to reach in the next 12 months. The expansion project came in on budget and approximately 4 months ahead of schedule.

At Blackrod, we continued to operate our successful SAGD pilot. The second well pair has been in production for over 4 years and, in 2017, produced an average of 490 bbl/d. Cumulatively, the second well pair has now produced in excess of 650,000 barrels of oil. The pilot generates positive cash flow and we are still collecting valuable operating data, so we expect to continue running the pilot for the next several years.

At Mooney, during 2017 we re-initiated a portion of the ASP flood and restarted some of the shut-in primary wells. Production from the re-initiated flood contributed to a 37% increase in production in 2017 to approximately 1,100 bbl/d. We will continue to ramp-up the flood in 2018 and likely expand the flood into other areas of the field in 2019.

Production averaged 10,600 boe/d in Q4 2017 and 10,199 boe/d for the year. The Onion Lake thermal project averaged 6,204 boe/d in Q4 2017, representing 58% of total production.

Q4 2017 revenue was $43 million, 23% higher than Q4 2016. For the year, oil and gas revenue was $151 million or 39% higher than 2016. The increase reflects higher oil prices in 2017.

Thermal operating costs, including energy costs, during the fourth quarter were under $9/bbl and for the full year were $9.88 per barrel. This reflects the positive performance of our Onion Lake thermal project. We expect to see additional cost improvements when production is ramped-up from the second phase of the project.

We maintained a strong balance sheet with year-end net debt of $117 million, well under our total current borrowing capacity of $195 million. We expect to exit 2018 with debt of $130 – $140 million.

Total capital costs in 2017 were $170 million, with the majority of costs related to the construction of phase 2 of the Onion Lake thermal project.

As previously announced, our updated proved plus probable independent reserves evaluation has a net present value, before tax, discounted at 10% of $2 billion, or approximately $6.00 per common share.

As a result of an expected steady ramp-up in production from our Onion Lake thermal expansion, our 2018 guidance anticipates we will exit 2018 at over 14,000 bbl/d, approximately 40% higher than our current production.

John Festival, President of BlackPearl, commented that “2017 was another successful year for BlackPearl. Our focus was to continue operating phase 1 of Onion Lake thermal at or above design capacity and to build phase 2 on time and within budget. We believe that Onion Lake is a top tier thermal project in Western Canada that provides long life, low decline, low cost production. We see additional expansion opportunities at Onion Lake over the next few years and we have sufficient reserves for 25+ years of activity. We should be able to fund this growth from our cash flows and our existing or expanded credit facilities without any additional dilution to shareholders. Longer-term, development of Onion Lake will put us in a better position to continue our growth with our Blackrod SAGD project.”

Financial and Operating Highlights

Three months ended
December 31,

Year ended
December 31,

2017

2016

2017

2016

Daily sales volumes

Oil (bbl/d)

10,026

9,853

9,611

9,391

Bitumen (bbl/d) (1)

481

523

490

556

10,507

10,376

10,101

9,947

Natural gas (mcf/d)

561

620

587

781

Combined (boe/d) (2)

10,600

10,479

10,199

10,077

Product pricing ($) (before the effects of hedging transactions)

Crude oil – per bbl

47.07

38.83

43.00

31.57

Natural gas – per mcf

1.45

2.90

2.01

1.95

Combined – per boe

46.71

38.61

42.69

31.30

Netback ($/boe)

Oil and gas sales

46.71

38.61

42.69

31.30

Realized gain (loss) on risk management contracts

(1.50)

0.63

0.10

3.10

Royalties

(6.34)

(4.93)

(5.96)

(3.96)

Transportation

(2.14)

(2.69)

(2.44)

(2.24)

Operating costs

(13.43)

(12.11)

(14.90)

(12.44)

Netback (5)

23.30

19.51

19.49

15.76

($000’s, except per share amounts)

Revenue

Oil and gas revenue – gross

43,486

35,360

151,286

109,066

Net income (loss) for the period

6,472

(2,217)

17,159

(19,928)

Per share, basic and diluted

0.02

(0.01)

0.05

(0.06)

Adjusted funds flow(4)

18,902

15,798

59,417

44,775

Cash flow from operating activities (3)

17,474

15,079

58,115

42,491

Capital expenditures

44,535

6,150

169,917

10,925

Working capital deficiency, end of period

23,912

4,591

23,912

4,591

Long term debt

92,944

–

92,944

–

Net debt (6)

116,856

4,591

116,856

4,591

Shares outstanding, end of period

336,267,235

335,948,895

336,267,235

335,948,895

(1)

Includes production from the Blackrod SAGD pilot. All sales and expenses from the Blackrod SAGD pilot are being recorded as an adjustment to the capitalized costs of the project until the technical feasibility and commercial viability of the project is established.

(2)

Boe is based on a conversion ratio of 6 mcf of natural gas to 1 bbl of oil. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and is not intended to represent a value equivalency at the wellhead.

(3)

Cash flow from operating activities is a GAAP measure and has a standardized meaning prescribed by Canadian GAAP.

(4)

Adjusted funds flow is a non-GAAP measure that represents cash flow from operating activities before decommissioning costs incurred and changes in non-cash working capital related to operations. Adjusted funds flow does not have standardized meanings prescribed by Canadian GAAP and therefore may not be comparable to similar measures used by other companies. See non-GAAP measures.

(5)

Netback is a non-GAAP measure that does not have a standardized meaning prescribed by Canadian GAAP and therefore may not be comparable to similar measures used by other companies. See non-GAAP measures.

(6)

Net debt is a non-GAAP measure. Net debt does not have a standardized meaning prescribed by GAAP and, therefore, may not be comparable to similar measures used by other companies in the oil and gas industry. See non-GAAP measures.

FOURTH QUARTER 2017 ACTIVITIES

Oil and natural gas sales increased 23% in the fourth quarter of 2017 to $43.5 million compared with $35.4 million in the same period in 2016. The increase in oil and gas sales is primarily attributable to a 21% increase in average sales price received in the fourth quarter.

Our realized oil price (before the effects of risk management activities) in the fourth quarter of 2017 was $47.07 per barrel compared to $38.83 per barrel for the same period in 2016. The increase in our realized wellhead price reflects higher WTI reference oil prices in Q4 2017 compared with Q3 2016 (US$55.40/bbl vs US$49.29/bbl), tighter heavy oil differentials (US$12.26/bbl vs US$14.34/bbl), partially offset by a stronger Canadian dollar relative to the US dollar ($0.786 vs $0.75).

BlackPearl sold an average of 10,600 boe/day during the fourth quarter of 2017 compared with 10,479 boe/day during the fourth quarter of 2016. During the fourth quarter the Onion Lake thermal project produced 6,204 barrels of oil per day, or 59% of total corporate production.

Production costs were $12.5 million or $13.43 per boe in the fourth quarter of 2017 compared to $11.1 million or $12.11 per boe in the fourth quarter of 2016. The increase from 2016 is mainly attributable to higher conventional production costs related to the restart of the ASP flood and re-activation of certain primary wells at Mooney in 2017. We are continuing to achieve low operating costs at our Onion Lake thermal project. Our thermal production costs in Q4 2017 were $8.17 per barrel. The lower production costs are due, in part, to lower natural gas input costs.

Three months ended
December 31

Year ended
December 31

2017

2016

2017

2016

Conventional Production

Production costs ($000s)

7,834

6,387

32,314

24,696

Per boe ($)

21.75

18.59

22.00

16.87

Thermal Production

Production costs ($000s)

4,664

4,701

20,497

18,638

Per boe ($)

8.17

8.35

9.88

9.22

Energy costs

2.30

3.74

3.56

3.47

Non-energy costs

5.87

4.61

6.32

5.75

Total Production

Production costs ($000s)

12,498

11,088

52,811

43,334

Per boe ($)

13.43

12.11

14.90

12.44

Net debt was $117 million at the end of 2017.

Adjusted funds flow in the fourth quarter of 2017 was $18.9 million, 20% higher compared with the fourth quarter of 2017. The increase reflects higher revenues in Q4 2017. Net income in Q4 2017 was $6.5 million compared to a loss of $2.2 million in Q4 2016.

Capital expenditures were $44.5 million in Q4 2017 and $170 million for the year. Spending was below our guidance estimates of $200 million. Lower capital expenditures in 2017 was primarily due to certain expenditures related to the expansion of the Onion Lake thermal project that were originally planned for 2017 being incurred in the first quarter of 2018.

2018 Outlook

Our initial guidance for 2018 was released in November 2017 and as a result of recent volatility in crude oil prices, we have updated our 2018 guidance. We are now assuming a WTI oil price of US $62/bbl and a heavy oil differential of US $21.50/bbl for planning and budget purposes. Capital spending in 2018 is now expected to be between $80 and $85 million, an increase from our original estimate of between $60 and $65 million. The change reflects costs related to Onion Lake thermal expansion that were originally forecast to be spent in 2017 that were not incurred until early in 2018. The focus of our 2018 capital spending continues to be the second phase of the Onion Lake thermal project. Currently, commissioning of the facilities and steam injection at the first well pad has started. For the remainder of 2018, our capital plans remain unchanged with drilling on some of our conventional heavy oil projects, the construction and drilling of a sustaining well pad for the Onion Lake thermal project and undertaking additional delineation drilling on our Blackrod lands.

A significant portion of these capital costs will continue to be funded with our anticipated adjusted funds flow, which is now budgeted to be between $60 and $65 million, an increase from our initial guidance of between $50 million and $55 million as the result of improved crude oil prices. As result of the increase in expected adjusted funds flow, our year-end 2018 debt levels decreased from our initial guidance of between $145 and $155 million to our current budget of between $130 and $140 million.

The average oil and gas production for 2018 remains unchanged and is expected to average between 11,000 and 12,000 boe/d. Exit production levels for 2018 of 14,000 boe/d also remain unchanged.

Other

The Company’s financial statements, notes to the financial statements, management’s discussion and analysis and Annual Information Form have been filed on SEDAR (www.sedar.com) and are also available on the Company’s website (www.blackpearlresources.ca).

BlackPearl’s annual meeting of shareholders will be held on May 3, 2018 in Calgary Alberta.

In particular, this release contains forward-looking statements pertaining to the expectation that we will initiate steam injection into future well pads at Onion Lake within a month, the expectation that the Onion Lake thermal project will reach 12,000 bbl/d within the next 12 months, the expectation that we will expand the Mooney ASP flood in 2019, the estimated net present value of our proved plus probable reserves of $2 billion, the expectation of costs improvements once the production from the Onion Lake expansion is ramped-up, our expectation that there are further expansion opportunities at Onion Lake and the expectation that this expansion can be funded from cash flows and our existing or expanded credit facilities and all the information under 2018 Outlook.

The forward-looking information is based on, among other things, expectations and assumptions by management regarding its future growth, future production levels, future oil and natural gas prices, continuation of existing tax, royalty and regulatory regimes, foreign exchange rates, estimates of future operating costs, timing and amount of capital expenditures, performance of existing and future wells, recoverability of the Company’s reserves and contingent resources, the ability to obtain financing on acceptable terms, availability of skilled labour and drilling and related equipment on a timely and cost efficient basis, general economic and financial market conditions, environment matters and the ability to market oil and natural gas successfully to current and new customers. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their nature, forward-looking statements involve numerous known and unknown risks and uncertainties that contribute to the possibility that actual results will differ from those anticipated in the forward looking statements. These risks include, but are not limited to, risks associated with fluctuations in market prices for crude oil, natural gas and diluent, general economic, market and business conditions, volatility of commodity inputs, substantial capital requirements, conditions including receipt of necessary regulatory and stock exchange approvals with respect to the issuance of common shares, uncertainties inherent in estimating quantities of reserves and resources, extent of, and cost of compliance with, government laws and regulations and the effect of changes in such laws and regulations from time to time, the need to obtain regulatory approvals on projects before development commences, environmental risks and hazards and the cost of compliance with environmental regulations, aboriginal claims, inherent risks and hazards with operations such as fire, explosion, blowouts, mechanical or pipe failure, cratering, oil spills, vandalism and other dangerous conditions, financial loss associated with derivative risk management contracts, potential cost overruns, variations in foreign exchange rates, variations in interest rates, diluent and water supply shortages, competition for capital, equipment, new leases, pipeline capacity and skilled personnel, uncertainties inherent in the SAGD bitumen and ASP recovery process, credit risks associated with counterparties, the failure of the Company or the holder of licences, leases and permits to meet requirements of such licences, leases and permits, reliance on third parties for pipelines and other infrastructure, changes in royalty regimes, failure to accurately estimate abandonment and reclamation costs, inaccurate estimates and assumptions by management, effectiveness of internal controls, the potential lack of available drilling equipment and other restrictions, failure to obtain or keep key personnel, title deficiencies with the Company’s assets, geo-political risks, risks that the Company does not have adequate insurance coverage, risk of litigation and risks arising from future acquisition activities. Readers are also cautioned that the foregoing list of factors is not exhaustive. Further information regarding these risk factors may be found under “Risk Factors” in the Annual Information Form.

Undue reliance should not be placed on these forward-looking statements. There can be no assurance that the plans, intentions or expectations upon which forward-looking statements are based will be realized. Actual results will differ, and the differences may be material and adverse to the Company and its shareholders. Furthermore, the forward-looking statements contained in this release are made as of the date hereof, and the Company does not undertake any obligation, except as required by applicable securities legislation, to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

Non-GAAP Measures

Throughout this release, the Company uses terms “adjusted funds flow”, “operating netback” and “net debt”. These terms do not have any standardized meaning as prescribed by GAAP and, therefore, may not be comparable with the calculation of similar measures presented by other issuers.

“Adjusted funds flow” is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs, decommissioning costs, debt repayments and other financial obligations. Adjusted funds flow is defined as cash flow from operating activities before decommissioning costs incurred and changes in non-cash working capital related to operations. Adjusted funds flow is not intended to represent cash flow from operating activities or other measures of financial performance in accordance with GAAP.

“Operating netback” is calculated as oil and gas revenues less royalties, production costs and transportation costs on a dollar basis and divided by total production for the period on a boe basis. Operating netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance against prior periods on a comparable basis. Our operating netback calculation is consistent with the definition found in the Canadian Oil and Gas Evaluation (COGE) Handbook.

“Net debt” is calculated as long-term debt less working capital for the period ended. Working capital consists of cash and cash equivalents, trade and other receivables, inventory, prepaid expenses and deposits, current portion of fair value of risk management assets less accounts payable and accrued liabilities, current portion of decommissioning liabilities and current portion of fair value of risk management liabilities. Management utilizes net debt as a key measure to assess the liquidity of the Company.

The information in this release is subject to the disclosure requirements of the Company under the EU Market Abuse Regulation and the Swedish Securities Markets Act. The information was publicly communicated on February 22, 2018 at 3:00 p.m. Mountain Time.

John Festival
President and Chief Executive Officer
Tel.: (403) 215-8313